1. Field of the Invention
This invention relates generally to rotary drill bits used in drilling subterranean wells and, more specifically, to rotary drill bits employing a torque limiting device allowing the drill string to rotate relative to the crown of the bit when a predetermined reactive torque is experienced by the crown of the drill bit.
2. State of the Art
The equipment used in drilling operations is well known in the art and generally comprises a drill bit attached to a drill string, including drill pipe and drill collars. A rotary table or other device such as a top drive may be employed to rotate the drill string, resulting in a corresponding rotation of the drill bit. The drill collars, which are heavier and stiffer than drill pipe, are normally used on the bottom part of the drill string to add weight to the drill bit. The weight of these drill collars assists in stabilizing the drill bit against the formation at the bottom of the borehole, causing it to drill when rotated. Too much weight on bit (WOB), however, may cause the drill bit to stall.
Downhole motors may also be employed to rotate the drill bit and include two basic components: a rotor, which is a steel shaft shaped in the form of a spiral or helix, and a stator, which is a molded rubber sleeve in a rigid tubular housing, that forms a spiral passageway to accommodate the rotor. When the rotor is fitted inside the stator, the difference in geometry between the two components creates a series of cavities through which drilling fluid is pumped. In doing so, the fluid displaces the rotor, forcing it to rotate as the fluid continues to flow between the rotor and the stator. An output shaft connected to the rotor transmits its rotation to the bit.
A typical rotary drill bit includes a bit body secured to a steel shank having a threaded pin connection for attaching the bit body to the drill string or the output shaft of a downhole motor and a crown comprising that part of the bit fitted with cutting structures for cutting into an earth formation. Generally, if the bit is a fixed-cutter or so-called "drag" bit, the cutting structure includes a series of cutting elements made of a superabrasive substance, such as polycrystalline diamond, oriented on the bit face at an angle to the surface being cut. On the other hand, if the bit has rotating cutters such as on a tri-cone bit, each cone independently rotates relative to the body of the bit and includes a series of protruding teeth, which may be integral with the cone or comprise separately-formed inserts.
The bit body of a drag bit is generally formed of steel or a matrix of hard particulate material such as tungsten carbide infiltrated with a binder, generally of copper-based alloy. In the case of steel body bits, the bit body is usually machined from round stock to the shape desired, usually with internal watercourses for delivery of drilling fluid to the bit face. Topographical features are then defined at precise locations on the bit face by machining, typically using a computer-controlled, five-axis machine tool. For a steel body bit, hardfacing may be applied to the bit face and to other critical areas of the bit exterior, and cutting elements are secured to the bit face, generally by inserting the proximal ends of studs on which the cutting elements are mounted into apertures bored in the bit face. The end of the bit body opposite the face is then threaded, made up and welded to the bit shank.
In the case of a matrix-type drag bit body, it is conventional to employ a preformed so-called bit "blank" of steel or other suitable material for internal reinforcement of the bit body matrix. The blank may be merely cylindrical and tubular, or may be fairly complex in configuration and include protrusions corresponding to blades, wings or other features on the bit face. Other preform elements comprised of sand, or in some instances tungsten carbide particles, in a flexible polymeric binder may also be employed to define internal watercourses and passages for delivery of drilling fluid to the bit face, as well as cutting element sockets, ridges, lands, nozzle displacements, junk slots and other external topographic features of the bit. The blank and other preforms are placed at appropriate locations in the mold used to cast the bit body before the mold is filled with tungsten carbide. The blank is bonded to and within the matrix upon cooling of the bit body after infiltration of the tungsten carbide with the binder in a furnace, and the other preforms are removed once the matrix has cooled. The threaded shank is then welded to the bit blank. The cutting elements (typically diamond, and most often a synthetic polycrystalline diamond compact, or PDC) may be bonded to the bit face by the solidified binder subsequent to furnacing of the bit body. Thermally stable PDCs, commonly termed "TSPs", may be bonded to the bit face by the furnacing process or may be subsequently bonded thereto, as by brazing, adhesive bonding, or mechanical affixation.
In order for the cutting elements to properly cut the formation during a drilling operation, considerable torque is required to generate the necessary rotational force between the cutting elements and the formation under a WOB substantial enough to ensure an adequate depth of cut. The resultant or reactive torque on the bit from formation contact is translated through the drill string and must be overcome by the means used to rotate the drill string, such as a rotary table, top drive, or downhole motor. In some instances, such as drilling through harder formations, the resultant torque may result in the winding up and sudden release of the drill string under torque, manifested as so-called "slaps" of the drill string at the rotary table. In other instances, torque may be sufficient to actually stop the bit from rotating. The rotary table may continue to rotate the drill string for some time, in effect "twisting" the drill string and placing the bit under very high torque loads before an operator realizes that the bit is no longer rotating. This problem is of particular concern with drag bits, due to direct engagement of the formation by the fixed PDC cutters, but also manifests itself with rock bits. If such a condition occurs and the rotary table continues to rotate, the drill string, the bit and/or components thereof may be damaged, or the drill string may even part under the torque load. If failure of the drill string occurs, the portion of the drill string above the break must be removed from the wellbore. A "fishing" assembly inserted into the wellbore is then normally employed in an attempt to retrieve the remainder of the drill string. If retrieval is impractical or unsuccessful, a new drilling assembly must be deflected, "sidetracked," or steered around the "fish." Any such scenario adds to the cost of production and results in down-time of the drilling operation while the remainder of the broken drill string is "tripped" from the wellbore and replaced with other bottom hole assemblies.
When a downhole motor is being used to rotate the drill bit, a sudden rise in surface pressure of the drilling fluid may indicate that the motor has stalled. While other conditions may cause a rise in fluid pressure, such as a clogged motor or plugged nozzles, if the motor stalls because the bit is no longer rotating due to excessive torque on the bit and is maintained in a stalled condition, the elastomeric stator lining may be damaged, preventing a proper interface between the stator and the rotor, thus requiring the motor to be tripped out of the wellbore and replaced. At the least, the bottomhole assembly including the motor must be pulled off-bottom and drilling and circulation recommenced to start the motor before the formation is re-engaged by the bit.
In addition to damage to drill strings and bits, directional drilling presents its own set of problems when excessive torque is applied to the drill bit. A directional well must intersect a target that may be several miles below the surface location of the drilling rig, and laterally offset therefrom. In order to reach the target, the wellbore must be directed or steered along a predetermined trajectory. The trajectory of the bit is typically determined by the tool face orientation (TFO), which must be maintained during drilling in order to maintain the trajectory of the wellbore toward the desired target. If the TFO shifts due to a stalled drill bit, the drilling must stop and a new TFO set as a reference point for the direction of drilling. While a shift in TFO is quickly manifested to the operator due to the essentially real-time nature of the MWD (measurement while drilling) mud-pulse transmissions, nonetheless, loss of TFO and resetting thereof results in considerable reduction in the overall rate of penetration (ROP) of the drilling assembly.
It would thus be advantageous to provide a drill bit assembly that includes a torque limiting device that is either an integral part of the bit construction or is attached near the bit between the drill bit and the drill string, or is positioned between the downhole motor and the drill bit.